waterflooding

Typically, an effective waterflood will recover as much oil as the primary development phase with the minimal incremental investment if waterflood was catered for during FDP. In some cases, the only way to economically develop a field is to go straight to EOR. For example, heavy California and Canadian oil often require steam EOR from the beginning to be economic. This short class is intended for general audiences who want to be exposed to the various EOR options especially the Gas/WAG processes. Key risk and uncertainties often associated with waterflood and Gas/WAG projects and de-risking strategies will be discussed.

Reservoir management for an economically successful chemical EOR project involves maintaining high injectivity to improve processing rates. In the Captain Field, horizontal injection wells offshore have been stimulated with surfactant-polymer fluids to reduce surrounding oil saturations and boost water relative permeability. The surfactant-polymer stimulation process described herein enables a step change in injectivity and advances the commercialization of this application. This paper explains the damage mechanism, laboratory chemical design, quality control through offshore field execution and data quantifying the results.

Phase behaviour laboratory experiments and analytical injectivity models are used to design a near wellbore clean-up and relative permeability improvement. Three field trials were conducted in wells that had observed significant injectivity decline over 1-3 years of polymer injection. Surfactant and polymer are blended with injection water and fluid quality is confirmed at the wellheads. Pressure is continuously monitored with injectivity index to determine the chemical efficiency and treatment longevity. Oil saturation changes and outflow profile distributions are analysed from well logs run before and after stimulating. Learnings are applied to refine the process for future well treatments.

The key execution elements include using polymer to provide adequate mobility control at high relative permeability and ensure contact along the entire wellbore. Repeatability of success with surfactant-polymer injection is demonstrated with decreased skin in all the wells. The key results include the oil saturation logs that prove the reduction of oil near the well completion and improves the relative permeability to aqueous phase. The results also prove to be sustainable over months of post-stimulation operation data with high injectivity.

Injectivity enhancement was supported by chemical quality control through the whole process. From laboratory to the field (from core flood experiments to dissolution of trapped oil near wellbore), surveillance measurements prove that the chemical design was maintained and executed successfully. The enhanced injectivity during clean-up allows for higher processing rate during polymer injection and negates the need for additional wells.

The application of surfactant-polymer technology can rejuvenate existing wells and avoid high costs associated with redrilling offshore wells. This improves processing rate for EOR methods and can even be applied to waterflood wells to improve the injectivity, e.g low permeability reservoirs.

Salinity of injection water plays a critical role in optimizing IOR/EOR methods, mainly in water flooding, low salinity water flooding and chemically enhanced oil recovery techniques, such as polymer floods. For such low salinity applications, preferred salinity is often between 1,000 and 5,000 mg/L TDS. On offshore platforms, this is achieved through blending permeate from low sulfate, high salinity (approximately 30,000 mg/l TDS) water train with desalinated water train (approximately 100 mg/l TDS). This practice typically requires two nanofiltration (NF) stages and one reverse osmosis (RO) stage which results in high footprint, heavy and complex blending manifolds. This study investigates the possibility of achieving the desired injection water composition employing a lower-footprint one pass assembly (i.e. without the need to blend permeates from parallel NF and RO trains) to produce the desired permeate salinity. The objective of the trial was to test a system providing a permeate TDS of 1,000 - 3,000 mg/L and sulfate levels lower than 10 mg/L. Such system should work with at least 20 L/m2h average fluxes and with a total recovery of at least 50 %. This paper discusses aninnovative way of arranging Nanofiltration and Reverse Osmosis membrane elements on offshore platforms in order to achieve the target salinity and sulfate concentrations for Low Salinity injection water Floods (LSF) and displays the results obtained during its testing in an industrial scale asset. The arrangement was operated during three months, showinga stable performance at an average flux of 20 L/m2h and with a recovery of 55%, using a configuration of seven membrane elements in series. Permeate water salinity obtained at this configuration was lower than 3,000 mg/L, maintaining low sulfate passage (<5 mg/L). Conclusions show the following benefits when using the innovative design:

Elimination of the blending system, thus reducing complex manifold and valves which will result in reduction of CAPEX and complexity.

Water Alternating Gas (WAG) injection is a widely practiced EOR method for many reservoirs. One drawback of WAG is the decreased injectivity when gas, often CO2, is injected into a previously water-flooded reservoir, and a further decline of injectivity is observed as water and gas injection are alternated. We present a workflow which allows the estimation of injectivity decline using pore scale displacement simulations and reservoir simulations.

In this approach, we use a multiphase Lattice Boltzmann method to directly simulate the alternating water-gas injection at pore scale resulting in a relative permeability curve for each injection phase. The simulation input accounts for injection rate, fluid properties and spatially varying wettability for each cycle during WAG. The final distribution of fluid phases in pore space of each displacement test is used as the starting point for the next displacement cycle. This enables the simulation of imbibition-drainage cycles. Any hysteresis effects present are typically captured in the resulting relative permeability curves. These are then used in a reservoir model to obtain an injectivity index for each injection phase.

We observe a strong decline of water relative permeability after the first gas injection cycle in an oil-wet rock. Detailed analysis of the fluid phases, in particular the water phase, shows that water is well connected after the initial water flood before gas injection. As gas is injected large water blobs are partially displaced and their size significantly reduced. For this wettability scenario, water and gas are competing for the large pore system. We find that capturing the hysteresis effect in a WAG requires the direct simulation of the displacement process, in particular known pore scale phenomena such as trapping and retraction.

The novelty of this approach is to directly capture the hysteresis effect of a WAG workflow in a direct simulation of displacement at pore scale. Emphasis is put on a detailed analysis of the multiphase displacement, including visualizations and an explanation for why the injectivity during WAG is reduced, namely, water and gas are competing for the same pore space. The presented workflow enables an a priori estimate for injectivity losses in a WAG EOR approach.

This paper addresses the challenges in modeling highly unstable waterflooding, using both a conventional Darcy-type simulator and an adaptive dynamic prenetwork model, by comparing the simulated results with experimental data including saturation maps. This paper presents key challenges in surface-facilities-project implementation during the construction and operational-readiness phase of a project and presents results from full-field implementation. We report a novel type of viscosity modifier relying on the supramolecular assemblies that have pH-adjustable viscosities and robust tolerance against high temperatures and salinities, and are resistant to shear-induced degradation.

This paper presents the performance results from one of the waterflood pilots in the Viewfield Bakken. An 18-well numerical-simulation model was built to represent an operator’s Lower Shaunavon waterflood-pilot area. Numerical simulation was used, and a history match on the pilot area was performed.

The authors detail the development of a technique based on surface-to-borehole controlled-source electromagnetics (CSEM), which exploits the large contrast in resistivity between injected water and oil to derive 3D resistivity distributions, proportional to saturations, in the reservoir. In the complete paper, the authors present a novel methodology to model interwell connectivity in mature waterfloods and achieve an improved reservoir-energy distribution and sweep pattern to maximize production performance by adjusting injection and production strategy on the well-control level. This paper addresses the challenges in modeling highly unstable waterflooding, using both a conventional Darcy-type simulator and an adaptive dynamic prenetwork model, by comparing the simulated results with experimental data including saturation maps. An integrated multidisciplinary approach is required to determine an optimal design and strategy. This paper reviews the design and implementation of a full-field interwell tracer program for a giant onshore oil field in Abu Dhabi.

This paper evaluates the incremental benefit of water injection in a conventional gas reservoir when compared with gas compression. This paper presents the performance results from one of the waterflood pilots in the Viewfield Bakken. Understanding of formation damage is a key theme in a waterflood project. An integrated multidisciplinary approach is required to determine an optimal design and strategy.

In this study, the authors investigated a fully data-driven approach using artificial neural networks (ANNs) for real-time virtual flowmetering and back-allocation in production wells. The authors present a new data-driven approach to estimate the injection rate in all noninstrumented wells in a large waterflooding operation accurately.

Early field tests suggest chemical treatments may be able to significantly increase production from unconventional formations. The low recovery rates observed in most shale reservoirs has prompted a number of research projects to develop new enhanced oil recovery methods. The Bakken’s ultratight, largely oil-wet nature limits the potential of waterflooding. As an alternative, an optimally spaced well-to-well surfactant-flooding technology is proposed.